Air intake chilling for combustion turbines is well known in the art and various cold sources have been employed. For example, numerous evaporative chillers with and without intermediate heat transfer fluids are described in U.S. Pat. No. 6,457,315. However, such configurations often consume significant quantities of energy for compression/condensation of a refrigerant, and are typically not thermally coupled to an otherwise available source of cold.
In other known configurations, refrigeration content of liquefied natural gas (LNG) is utilized to chill intake air, wherein the air chilling and/or certain other processes contribute to vaporization of LNG in a vaporizer. For example, in one known configuration, as described in U.S. Pat. App. No. 2003/0182941, LNG is used as a refrigerant that is then at least partially routed back to a stratified tank, while another portion is vaporized. In still another known configuration, as taught in U.S. Pat. No. 5,626,019 or EP 0651145, LNG is used as a cold source to cool an intermediary refrigerant for intake air chilling, wherein the so vaporized natural gas is then used as a fuel. Similarly, as described in EP 0605159, inlet air can be cross exchanged with LNG to provide both vaporized fuel and chilled intake air. While such plant configurations typically operate satisfactorily to at least some degree, various disadvantages remain. Among other things, the quantity of regasified LNG is relatively low as compared, for example, with a relatively large volume that is typically required for pipeline transmission.
To overcome such disadvantages, larger quantities of LNG can be regasified using a heat exchange fluid that is (re)heated by heat exchange with turbine intake air and seawater as described in U.S. Pat. No. 6,367,258. In still further known configurations, LNG cold is used as a heat sink in a steam cycle as taught in U.S. Pat. App. No. 2005/0223712. Alternatively, combined cycle plant configurations are also known in which heat from a heat transfer fluid is employed to regasify LNG, and wherein the chilled heat transfer fluid is reheated using intake air chilling and heat from the heat recovery steam generator as described in U.S. Pat. App. No. 2003/0005698, U.S. Pat. No. 6,374,591, EP 0683847, or EP 0828915. Still further known plants integrate LNG regasification with power production and specific demethanizing and/or deethanizing operations as described in WO 2004/109206.
While such configurations often advantageously integrate regasification of LNG with another, typically power generating process, various disadvantages remain. For example, most of these processes are typically limited to cool the gas turbine intake air to 50° F. (or even higher) to avoid water freezing of the intake air, which would create unsafe conditions or even making the power plant inoperable. Therefore, improvements in power generation efficiency using LNG refrigeration content in known plants is typically limited by the cooling limit of the intake air temperature. Moreover, while all or almost all of the currently known gas turbine air pre-cool methods tend to improve the power generation efficiencies in hot climate regions (e.g., in the tropics or sub-tropics), they are often not suitable in colder climate regions (e.g., northeastern parts of North America). Even in relatively hot climate, such configurations provide very marginal efficiency benefits only in the summer months, with decreasing benefits in the winter seasons. Worse yet, in some cases operation of these known processes must be discontinued when the ambient temperatures drop below 45° F. to avoid water freezing at the air intake and machinery damage by ice blockage.
Therefore, while numerous processes and configurations for power plants with LNG utilization and/or regasification are known in the art, all of almost all of them suffer from one or more disadvantages. Thus, there is still a need to provide improved configurations and methods for power plants with LNG utilization and regasification.